The present invention relates to a process for the catalytic hydrotreating of silicon containing hydrocarbon feed stock.
A catalytic reformer and its associated hydrotreater are found in every modern refinery. With the advent of bimetallic reforming catalysts, sulphur and nitrogen are required to be very low in the reformer feed normally less than 0.5 ppm. Naphtha hydrofiner, processing straight-run feeds, meet these requirements while achieving cycle lengths of greater than 3 years even with low activity or regenerated catalysts.
Because of its low installation cost relative to other options, the delayed coker is often the system of choice for upgrading residual oils. However, delayed coker products cause additional processing difficulties in downstream units, particularly hydrotreaters and reforming catalysts are found to be sensitive to silicon deposits. For example, the residue from silicone oils used to prevent foaming in coker drums largely distils in the naphtha range and can cause catalyst deactivation in downstream naphtha hydrofiners and reforming units.
As further an example, naphtha is contaminated by silicon when silicone oil is injected in the well during petroleum extraction in deep water.
The origin of silicon deposits on naphtha hydrotreating catalysts can be traced back to the silicone oil added to the heavy residue feed of the delayed coker or to the silicone oil added to the silicone dwell (Kellberg, L., Zeuthen, P. and Jakobsen, H. J., Deactivation of HDT catalysts by formation of silica gels from silicone oil. Characterisation of spent catalysts from HDT of coker naphtha using 29Si and 13C CP/MAS NMR, J. Catalysis 143, 45-51 (1993)).
Because of gas formation, silicone oil (polydimethylsiloxane, PDMS) is usually added to the coker drums to suppress foaming. This silicone oil usually cracks or decomposes in the coker to form modified silica gels and fragments. These gels and fragments mainly distil in the naphtha range and are passed to a hydrotreater together with the coker naphtha. Other coker products will also contain some silicon, but usually at lower concentrations than in naphtha products.
Silica poisoning is a severe problem when hydroprocessing coker naphthas. The catalyst operation time will typically depend on the amount of silicon being introduced with the feedstock and on silicon “tolerance” of the applied catalyst system. In absence of silicon in the feed, most naphtha hydroprocessing catalyst cycle lengths exceed three years. Deposition of silicon in form of a silica gel with a partially methylated surface from coker naphthas deactivates the catalyst and reduces the typical HDS/HDN unit cycle lengths often to less than one year.
By selection of an appropriate catalyst, unit cycle lengths can be significantly extended over most typical naphtha hydrotreating catalysts.
Typical conditions for naphtha pre-treatment reactors are total pressures between 15 and 50 bars; average reactor temperature between 50° C. and 400° C. The exact conditions will depend on type of feedstock, the required degree of desulphurisation and the desired run length. The end of the run is normally reached when the naphtha leaving the reactor contains detective amounts of silicon.
For a refiner, the run length is a very important consideration. A shorter run length incurs high cost due to frequent catalyst replacement and extended downtime (time off-stream) for catalyst replacement resulting in loss of revenue because of less production of naphtha and feed to the reforming unit.
It is known from EP 1,188,811 to increase operation time of hydrotreating reactors for treatment of silicon containing feedstock, when moistening the hydrotreating catalyst is moisturised with an amount of water added to the feed stock.
Silicon uptake depends on type of catalyst and temperatures in the hydrotreater. An increase in temperature results in a higher uptake of the contaminants.
In a hydrotreating unit employing a single reactor, however, the inlet temperature is controlled by the sulphur removal reactions, which at a reactor outlet temperature of above 350° C. will result in recombination of sulphur compounds depending on the feed stock composition.
In the known hydrotreaters with a single reactor for the removal of silicon compounds and HDS/HDN, the process fluid leaving the silicon removal catalyst bed has to be cooled by quenching with cold hydrogen make-up gas and with cooled liquid product. Quenching with liquid product disadvantageously reduces the actual hydrogen partial-pressure, which must be compensated by raising the total operation pressure.
The general object of the invention is to improve efficiency and to increase operation time of hydrotreating reactors for treatment of silicon containing feedstock by improving run time length and silicon capacity of hydrotreating catalysts.